System and method for optimizing drilling with a rotary steerable system

ABSTRACT

A system and method for optimizing drilling with a rotary steerable system may monitor downhole signals associated with vibrational loads along a drill string during drilling. A downhole controller at a rotary steerable bottom-hole adapter may generate a control indication for modifying drilling parameters of a drill bit in response to detecting harmful vibrational loads for the drill string. A modification of the drilling speed and direction of the drill bit used for drilling may be performed based on the control indication.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority of U.S. Patent Application Ser. No. 62/729,944, filed on Sep. 11, 2018, and entitled “System and Method for Drilling with a Rotary Steerable Tool,” which is hereby incorporated by reference as if fully set forth herein.

BACKGROUND Field of the Disclosure

The present disclosure provides systems and methods useful for optimizing drilling with a rotary steerable system. The systems and methods can be computer-implemented using processor executable instructions for execution on a processor and can accordingly be executed with a programmed computer system.

Description of the Related Art

Drilling a borehole for the extraction of minerals has become an increasingly complicated operation due to the increased depth and complexity of many boreholes, including the complexity added by directional drilling. Drilling is an expensive operation and errors in drilling add to the cost and, in some cases, drilling errors may permanently lower the output of a well for years into the future. Conventional technologies and methods may not adequately address the complicated nature of drilling, and may not be capable of gathering and processing various information from downhole sensors and surface control systems in a timely manner, in order to improve drilling operations and minimize drilling errors.

During drilling operations, the reactive loads placed on rotary steerable systems (RSS) or tools used for drilling with a drill bit can cause harmful vibrational loads that can cause drilling equipment to break, or wear out quickly. In some cases, the harmful vibrational loads can be caused when vibrations excited by the interaction of the drill bit and the borehole are associated with resonant frequencies of the drill bit, the bottom hole assembly (BHA), or the drill string, among other drilling equipment. In some cases, the harmful vibrational loads can be caused by the drill bit continuously sticking and springing forward (e.g., a stick-slip condition) that can cause damage as the torsional strain of the drill string unwinds in an uncontrollable manner.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

FIG. 1 is a depiction of a drilling system for drilling a borehole;

FIG. 2 is a depiction of a drilling environment including the drilling system for drilling a borehole;

FIG. 3 is a depiction of a borehole generated in the drilling environment;

FIG. 4 is a depiction of a drilling architecture including the drilling environment;

FIG. 5 is a depiction of rig control systems included in the drilling system;

FIG. 6 is a depiction of algorithm modules used by the rig control systems;

FIG. 7 is a depiction of a steering control process used by the rig control systems;

FIG. 8 is a depiction of a graphical user interface provided by the rig control systems;

FIG. 9 is a depiction of a guidance control loop performed by the rig control systems;

FIG. 10 is a depiction of a controller usable by the rig control systems;

FIG. 11 is a depiction of drill string and drill bit rotation using a rotary steerable BHA;

FIG. 12 is a depiction of drill string and drill bit rotation using a rotary steerable BHA;

FIG. 13 is a flow chart of a method for RSS drilling; and

FIG. 14 is a flow chart of a method for RSS drilling.

DESCRIPTION OF PARTICULAR EMBODIMENT(S)

In the following description, details are set forth by way of example to facilitate discussion of the disclosed subject matter. It is noted, however, that the disclosed embodiments are exemplary and not exhaustive of all possible embodiments.

Throughout this disclosure, a hyphenated form of a reference numeral refers to a specific instance of an element and the un-hyphenated form of the reference numeral refers to the element generically or collectively. Thus, as an example (not shown in the drawings), device “12-1” refers to an instance of a device class, which may be referred to collectively as devices “12” and any one of which may be referred to generically as a device “12”. In the figures and the description, like numerals are intended to represent like elements.

Drilling a well typically involves a substantial amount of human decision-making during the drilling process. For example, geologists and drilling engineers use their knowledge, experience, and the available information to make decisions on how to plan the drilling operation, how to accomplish the drilling plan, and how to handle issues that arise during drilling. However, even the best geologists and drilling engineers perform some guesswork due to the unique nature of each borehole. Furthermore, a directional human driller performing the drilling may have drilled other boreholes in the same region and so may have some similar experience. However, during drilling operations, a multitude of input information and other factors may affect a drilling decision being made by a human operator or specialist, such that the amount of information may overwhelm the cognitive ability of the human to properly consider and factor into the drilling decision. Furthermore, the quality or the error involved with the drilling decision may improve with larger amounts of input data being considered, for example, such as formation data from a large number of offset wells. For these reasons, human specialists may be unable to achieve desirable drilling decisions, particularly when such drilling decisions are made under time constraints, such as during drilling operations when continuation of drilling is dependent on the drilling decision and, thus, the entire drilling rig waits idly for the next drilling decision. Furthermore, human decision-making for drilling decisions can result in expensive mistakes, because drilling errors can add significant cost to drilling operations. In some cases, drilling errors may permanently lower the output of a well, resulting in substantial long term economic losses due to the lost output of the well.

Therefore, the well plan may be updated based on new stratigraphic information from the wellbore, as it is being drilled. This stratigraphic information can be gained on one hand from Measurement While Drilling (MWD) and Logging While Drilling (LWD) sensor data, but could also include other reference well data, such as drilling dynamics data or sensor data giving information, for example, on the hardness of the rock in individual strata layers being drilled through.

A method for updating the well plan with additional stratigraphic data may first combine the various parameters into a single characteristic function, both for the subject well and every offset well. For every pair of subject well and offset well, a heat map can be computed to display the misfit between the characteristic functions of the subject and offset wells. The heat maps may then enable the identification of paths (x(MD), y(MD)), parameterized by the measured depth (MD) along the subject well. These paths uniquely describe the vertical depth of the subject well relative to the geology (e.g., formation) at every offset well. Alternatively, the characteristic functions of the offset wells can be combined into a single characteristic function at the location of the subject wellbore. This combined characteristic function changes along the subject well with changes in the stratigraphy. The heat map may also be used to identify stratigraphic anomalies, such as structural faults, stringers and breccia. The identified paths may be used in updating the well plan with the latest data to steer the wellbore into the geological target(s) and keep the wellbore in the target zone.

Referring now to the drawings, Referring to FIG. 1, a drilling system 100 is illustrated in one embodiment as a top drive system. As shown, the drilling system 100 includes a derrick 132 on the surface 104 of the earth and is used to drill a borehole 106 into the earth. Typically, drilling system 100 is used at a location corresponding to a geographic formation 102 in the earth that is known.

In FIG. 1, derrick 132 includes a crown block 134 to which a traveling block 136 is coupled via a drilling line 138. In drilling system 100, a top drive 140 is coupled to traveling block 136 and may provide rotational force for drilling. A saver sub 142 may sit between the top drive 140 and a drill pipe 144 that is part of a drill string 146. Top drive 140 may rotate drill string 146 via the saver sub 142, which in turn may rotate a drill bit 148 of a bottom hole assembly (BHA) 149 in borehole 106 passing through formation 102. Also visible in drilling system 100 is a rotary table 162 that may be fitted with a master bushing 164 to hold drill string 146 when not rotating.

A mud pump 152 may direct a fluid mixture 153 (e.g., a mud mixture) from a mud pit 154 into drill string 146. Mud pit 154 is shown schematically as a container, but it is noted that various receptacles, tanks, pits, or other containers may be used. Mud 153 may flow from mud pump 152 into a discharge line 156 that is coupled to a rotary hose 158 by a standpipe 160. Rotary hose 158 may then be coupled to top drive 140, which includes a passage for mud 153 to flow into borehole 106 via drill string 146 from where mud 153 may emerge at drill bit 148. Mud 153 may lubricate drill bit 148 during drilling and, due to the pressure supplied by mud pump 152, mud 153 may return via borehole 106 to surface 104.

In drilling system 100, drilling equipment (see also FIG. 5) is used to perform the drilling of borehole 106, such as top drive 140 (or rotary drive equipment) that couples to drill string 146 and BHA 149 and is configured to rotate drill string 146 and apply pressure to drill bit 148. Drilling system 100 may include control systems such as a WOB/differential pressure control system 522, a positional/rotary control system 524, a fluid circulation control system 526, and a sensor system 528, as further described below with respect to FIG. 5. The control systems may be used to monitor and change drilling rig settings, such as the WOB or differential pressure to alter the ROP or the radial orientation of the tool face, change the flow rate of drilling mud, and perform other operations. Sensor system 528 may be for obtaining sensor data about the drilling operation and drilling system 100, including the downhole equipment. For example, sensor system 528 may include MWD or logging while drilling (LWD) tools for acquiring information, such as tool face and formation logging information, that may be saved for later retrieval, transmitted with or without a delay using any of various communication means (e.g., wireless, wireline, or mud pulse telemetry), or otherwise transferred to steering control system 168. As used herein, an MWD tool is enabled to communicate downhole measurements without substantial delay to the surface 104, such as using mud pulse telemetry, while a LWD tool is equipped with an internal memory that stores measurements when downhole and can be used to download a stored log of measurements when the LWD tool is at the surface 104. The internal memory in the LWD tool may be a removable memory, such as a universal serial bus (USB) memory device or another removable memory device. It is noted that certain downhole tools may have both MWD and LWD capabilities. Such information acquired by sensor system 528 may include information related to hole depth, bit depth, inclination angle, azimuth angle, true vertical depth, gamma count, standpipe pressure, mud flow rate, rotary rotations per minute (RPM), bit speed, ROP, WOB, among other information. It is noted that all or part of sensor system 528 may be incorporated into a control system, or in another component of the drilling equipment. As drilling system 100 can be configured in many different implementations, it is noted that different control systems and subsystems may be used.

Sensing, detection, measurement, evaluation, storage, alarm, and other functionality may be incorporated into a downhole tool 166 or BHA 149 or elsewhere along drill string 146 to provide downhole surveys of borehole 106. Accordingly, downhole tool 166 may be an MWD tool or a LWD tool or both, and may accordingly utilize connectivity to the surface 104, local storage, or both. In different implementations, gamma radiation sensors, magnetometers, accelerometers, and other types of sensors may be used for the downhole surveys. Although downhole tool 166 is shown in singular in drilling system 100, it is noted that multiple instances (not shown) of downhole tool 166 may be located at one or more locations along drill string 146.

In some embodiments, formation detection and evaluation functionality may be provided via a steering control system 168 on the surface 104. Steering control system 168 may be located in proximity to derrick 132 or may be included with drilling system 100. In other embodiments, steering control system 168 may be remote from the actual location of borehole 106 (see also FIG. 4). For example, steering control system 168 may be a stand-alone system or may be incorporated into other systems included with drilling system 100.

In operation, steering control system 168 may be accessible via a communication network (see also FIG. 10), and may accordingly receive formation information via the communication network. In some embodiments, steering control system 168 may use the evaluation functionality to provide corrective measures, such as a convergence plan to overcome an error in the well trajectory of borehole 106 with respect to a reference, or a planned well trajectory. The convergence plans or other corrective measures may depend on a determination of the well trajectory, and therefore, may be improved in accuracy using surface steering, as disclosed herein.

In particular embodiments, at least a portion of steering control system 168 may be located in downhole tool 166 (not shown). In some embodiments, steering control system 168 may communicate with a separate controller (not shown) located in downhole tool 166. In particular, steering control system 168 may receive and process measurements received from downhole surveys, and may perform the calculations described herein for surface steering using the downhole surveys and other information referenced herein.

In drilling system 100, to aid in the drilling process, data is collected from borehole 106, such as from sensors in BHA 149, downhole tool 166, or both. The collected data may include the geological characteristics of formation 102 in which borehole 106 was formed, the attributes of drilling system 100, including BHA 149, and drilling information such as weight-on-bit (WOB), drilling speed, and other information pertinent to the formation of borehole 106. The drilling information may be associated with a particular depth or another identifiable marker to index collected data. For example, the collected data for borehole 106 may capture drilling information indicating that drilling of the well from 1,000 feet to 1,200 feet occurred at a first rate of penetration (ROP) through a first rock layer with a first WOB, while drilling from 1,200 feet to 1,500 feet occurred at a second ROP through a second rock layer with a second WOB (see also FIG. 2). In some applications, the collected data may be used to virtually recreate the drilling process that created borehole 106 in formation 102, such as by displaying a computer simulation of the drilling process. The accuracy with which the drilling process can be recreated depends on a level of detail and accuracy of the collected data, including collected data from a downhole survey of the well trajectory.

The collected data may be stored in a database that is accessible via a communication network for example. In some embodiments, the database storing the collected data for borehole 106 may be located locally at drilling system 100, at a drilling hub that supports a plurality of drilling systems 100 in a region, or at a database server accessible over the communication network that provides access to the database (see also FIG. 4). At drilling system 100, the collected data may be stored at the surface 104 or downhole in drill string 146, such as in a memory device included with BHA 149 (see also FIG. 10). Alternatively, at least a portion of the collected data may be stored on a removable storage medium, such as using steering control system 168 or BHA 149, that is later coupled to the database in order to transfer the collected data to the database, which may be manually performed at certain intervals, for example.

In FIG. 1, steering control system 168 is located at or near the surface 104 where borehole 106 is being drilled. Steering control system 168 may be coupled to equipment used in drilling system 100 and may also be coupled to the database, whether the database is physically located locally, regionally, or centrally (see also FIGS. 4 and 5). Accordingly, steering control system 168 may collect and record various inputs, such as measurement data from a magnetometer and an accelerometer that may also be included with BHA 149.

Steering control system 168 may further be used as a surface steerable system, along with the database, as described above. The surface steerable system may enable an operator to plan and control drilling operations while drilling is being performed. The surface steerable system may itself also be used to perform certain drilling operations, such as controlling certain control systems that, in turn, control the actual equipment in drilling system 100 (see also FIG. 5). The control of drilling equipment and drilling operations by steering control system 168 may be manual, manual-assisted, semi-automatic, or automatic, in different embodiments.

Manual control may involve direct control of the drilling rig equipment, albeit with certain safety limits to prevent unsafe or undesired actions or collisions of different equipment. To enable manual-assisted control, steering control system 168 may present various information, such as using a graphical user interface (GUI) displayed on a display device (see FIG. 8), to a human operator, and may provide controls that enable the human operator to perform a control operation. The information presented to the user may include live measurements and feedback from the drilling rig and steering control system 168, or the drilling rig itself, and may further include limits and safety-related elements to prevent unwanted actions or equipment states, in response to a manual control command entered by the user using the GUI.

To implement semi-automatic control, steering control system 168 may itself propose or indicate to the user, such as via the GUI, that a certain control operation, or a sequence of control operations, should be performed at a given time. Then, steering control system 168 may enable the user to imitate the indicated control operation or sequence of control operations, such that once manually started, the indicated control operation or sequence of control operations is automatically completed. The limits and safety features mentioned above for manual control would still apply for semi-automatic control. It is noted that steering control system 168 may execute semi-automatic control using a secondary processor, such as an embedded controller that executes under a real-time operating system (RTOS), that is under the control and command of steering control system 168. To implement automatic control, the step of manual starting the indicated control operation or sequence of operations is eliminated, and steering control system 168 may proceed with only a passive notification to the user of the actions taken.

In order to implement various control operations, steering control system 168 may perform (or may cause to be performed) various input operations, processing operations, and output operations. The input operations performed by steering control system 168 may result in measurements or other input information being made available for use in any subsequent operations, such as processing or output operations. The input operations may accordingly provide the input information, including feedback from the drilling process itself, to steering control system 168. The processing operations performed by steering control system 168 may be any processing operation associated with surface steering, as disclosed herein. The output operations performed by steering control system 168 may involve generating output information for use by external entities, or for output to a user, such as in the form of updated elements in the GUI, for example. The output information may include at least some of the input information, enabling steering control system 168 to distribute information among various entities and processors.

In particular, the operations performed by steering control system 168 may include operations such as receiving drilling data representing a drill path, receiving other drilling parameters, calculating a drilling solution for the drill path based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at the drilling rig, monitoring the drilling process to gauge whether the drilling process is within a defined margin of error of the drill path, and calculating corrections for the drilling process if the drilling process is outside of the margin of error.

Accordingly, steering control system 168 may receive input information either before drilling, during drilling, or after drilling of borehole 106. The input information may comprise measurements from one or more sensors, as well as survey information collected while drilling borehole 106. The input information may also include a well plan, a regional formation history, drilling engineer parameters, downhole tool face/inclination information, downhole tool gamma/resistivity information, economic parameters, reliability parameters, among various other parameters. Some of the input information, such as the regional formation history, may be available from a drilling hub 410, which may have respective access to a regional drilling database (DB) 412 (see FIG. 4). Other input information may be accessed or uploaded from other sources to steering control system 168. For example, a web interface may be used to interact directly with steering control system 168 to upload the well plan or drilling parameters.

As noted, the input information may be provided to steering control system 168. After processing by steering control system 168, steering control system 168 may generate control information that may be output to drilling rig 210 (e.g., to rig controls 520 that control drilling equipment 530, see also FIGS. 2 and 5). Drilling rig 210 may provide feedback information using rig controls 520 to steering control system 168. The feedback information may then serve as input information to steering control system 168, thereby enabling steering control system 168 to perform feedback loop control and validation. Accordingly, steering control system 168 may be configured to modify its output information to the drilling rig, in order to achieve the desired results, which are indicated in the feedback information. The output information generated by steering control system 168 may include indications to modify one or more drilling parameters, the direction of drilling, the drilling mode, among others. In certain operational modes, such as semi-automatic or automatic, steering control system 168 may generate output information indicative of instructions to rig controls 520 to enable automatic drilling using the latest location of BHA 149. Therefore, an improved accuracy in the determination of the location of BHA 149 may be provided using steering control system 168, along with the methods and operations for surface steering disclosed herein.

Referring now to FIG. 2, a drilling environment 200 is depicted schematically and is not drawn to scale or perspective. In particular, drilling environment 200 may illustrate additional details with respect to formation 102 below the surface 104 in drilling system 100 shown in FIG. 1. In FIG. 2, drilling rig 210 may represent various equipment discussed above with respect to drilling system 100 in FIG. 1 that is located at the surface 104.

In drilling environment 200, it may be assumed that a drilling plan (also referred to as a well plan) has been formulated to drill borehole 106 extending into the ground to a true vertical depth (TVD) 266 and penetrating several subterranean strata layers. Borehole 106 is shown in FIG. 2 extending through strata layers 268-1 and 270-1, while terminating in strata layer 272-1. Accordingly, as shown, borehole 106 does not extend or reach underlying strata layers 274-1 and 276-1. A target area 280 specified in the drilling plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1. It is noted that target area 280 may be of any shape and size, and may be defined using various different methods and information in different embodiments. In some instances, target area 280 may be specified in the drilling plan using subsurface coordinates, or references to certain markers, that indicate where borehole 106 is to be terminated. In other instances, target area may be specified in the drilling plan using a depth range within which borehole 106 is to remain. For example, the depth range may correspond to strata layer 272-1. In other examples, target area 280 may extend as far as can be realistically drilled. For example, when borehole 106 is specified to have a horizontal section with a goal to extend into strata layer 172 as far as possible, target area 280 may be defined as strata layer 272-1 itself and drilling may continue until some other physical limit is reached, such as a property boundary or a physical limitation to the length of the drill string.

Also visible in FIG. 2 is a fault line 278 that has resulted in a subterranean discontinuity in the fault structure. Specifically, strata layers 268, 270, 272, 274, and 276 have portions on either side of fault line 278. On one side of fault line 278, where borehole 106 is located, strata layers 268-1, 270-1, 272-1, 274-1, and 276-1 are unshifted by fault line 278. On the other side of fault line 278, strata layers 268-2, 270-3, 272-3, 274-3, and 276-3 are shifted downwards by fault line 278.

Current drilling operations frequently include directional drilling to reach a target, such as target area 280. The use of directional drilling has been found to generally increase an overall amount of production volume per well, but also may lead to significantly higher production rates per well, which are both economically desirable. As shown in FIG. 2, directional drilling may be used to drill the horizontal portion of borehole 106, which increases an exposed length of borehole 106 within strata layer 272-1, and which may accordingly be beneficial for hydrocarbon extraction from strata layer 272-1. Directional drilling may also be used alter an angle of borehole 106 to accommodate subterranean faults, such as indicated by fault line 278 in FIG. 2. Other benefits that may be achieved using directional drilling include sidetracking off of an existing well to reach a different target area or a missed target area, drilling around abandoned drilling equipment, drilling into otherwise inaccessible or difficult to reach locations (e.g., under populated areas or bodies of water), providing a relief well for an existing well, and increasing the capacity of a well by branching off and having multiple boreholes extending in different directions or at different vertical positions for the same well. Directional drilling is often not limited to a straight horizontal borehole 106, but may involve staying within a strata layer that varies in depth and thickness as illustrated by strata layer 172. As such, directional drilling may involve multiple vertical adjustments that complicate the trajectory of borehole 106.

Referring now to FIG. 3, one embodiment of a portion of borehole 106 is shown in further detail. Using directional drilling for horizontal drilling may introduce certain challenges or difficulties that may not be observed during vertical drilling of borehole 106. For example, a horizontal portion 318 of borehole 106 may be started from a vertical portion 310. In order to make the transition from vertical to horizontal, a curve may be defined that specifies a so-called “build up” section 316. Build up section 316 may begin at a kick off point 312 in vertical portion 310 and may end at a begin point 314 of horizontal portion 318. The change in inclination in build up section 316 per measured length drilled is referred to herein as a “build rate” and may be defined in degrees per one hundred feet drilled. For example, the build rate may have a value of 6°/100 ft., indicating that there is a six degree change in inclination for every one hundred feet drilled. The build rate for a particular build up section may remain relatively constant or may vary.

The build rate used for any given build up section may depend on various factors, such as properties of the formation (i.e., strata layers) through which borehole 106 is to be drilled, the trajectory of borehole 106, the particular pipe and drill collars/BHA components used (e.g., length, diameter, flexibility, strength, mud motor bend setting, and drill bit), the mud type and flow rate, the specified horizontal displacement, stabilization, and inclination, among other factors. An overly aggressive built rate can cause problems such as severe doglegs (e.g., sharp changes in direction in the borehole) that may make it difficult or impossible to run casing or perform other operations in borehole 106. Depending on the severity of any mistakes made during directional drilling, borehole 106 may be enlarged or drill bit 146 may be backed out of a portion of borehole 106 and redrilled along a different path. Such mistakes may be undesirable due to the additional time and expense involved. However, if the built rate is too cautious, additional overall time may be added to the drilling process, because directional drilling generally involves a lower ROP than straight drilling. Furthermore, directional drilling for a curve is more complicated than vertical drilling and the possibility of drilling errors increases with directional drilling (e.g., overshoot and undershoot that may occur while trying to keep drill bit 148 on the planned trajectory).

Two modes of drilling, referred to herein as “rotating” and “sliding”, are commonly used to form borehole 106. Rotating, also called “rotary drilling”, uses top drive 140 or rotary table 162 to rotate drill string 146. Rotating may be used when drilling occurs along a straight trajectory, such as for vertical portion 310 of borehole 106. Sliding, also called “steering” or “directional drilling” as noted above, typically uses a mud motor located downhole at BHA 149. The mud motor may have an adjustable bent housing and is not powered by rotation of the drill string. Instead, the mud motor uses hydraulic power derived from the pressurized drilling mud that circulates along borehole 106 to and from the surface 104 to directionally drill borehole 106 in build up section 316.

Thus, sliding is used in order to control the direction of the well trajectory during directional drilling. A method to perform a slide may include the following operations. First, during vertical or straight drilling, the rotation of drill string 146 is stopped. Based on feedback from measuring equipment, such as from downhole tool 166, adjustments may be made to drill string 146, such as using top drive 140 to apply various combinations of torque, WOB, and vibration, among other adjustments. The adjustments may continue until a tool face is confirmed that indicates a direction of the bend of the mud motor is oriented to a direction of a desired deviation (i.e., build rate) of borehole 106. Once the desired orientation of the mud motor is attained, WOB to the drill bit is increased, which causes the drill bit to move in the desired direction of deviation. Once sufficient distance and angle have been built up in the curved trajectory, a transition back to rotating mode can be accomplished by rotating the drill string again. The rotation of the drill string after sliding may neutralize the directional deviation caused by the bend in the mud motor due to the continuous rotation around a centerline of borehole 106.

Referring now to FIG. 4, a drilling architecture 400 is illustrated in diagram form. As shown, drilling architecture 400 depicts a hierarchical arrangement of drilling hubs 410 and a central command 414, to support the operation of a plurality of drilling rigs 210 in different regions 402. Specifically, as described above with respect to FIGS. 1 and 2, drilling rig 210 includes steering control system 168 that is enabled to perform various drilling control operations locally to drilling rig 210. When steering control system 168 is enabled with network connectivity, certain control operations or processing may be requested or queried by steering control system 168 from a remote processing resource. As shown in FIG. 4, drilling hubs 410 represent a remote processing resource for steering control system 168 located at respective regions 402, while central command 414 may represent a remote processing resource for both drilling hub 410 and steering control system 168.

Specifically, in a region 401-1, a drilling hub 410-1 may serve as a remote processing resource for drilling rigs 210 located in region 401-1, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, drilling hub 410-1 may have access to a regional drilling DB 412-1, which may be local to drilling hub 410-1. Additionally, in a region 401-2, a drilling hub 410-2 may serve as a remote processing resource for drilling rigs 210 located in region 401-2, which may vary in number and are not limited to the exemplary schematic illustration of FIG. 4. Additionally, drilling hub 410-2 may have access to a regional drilling DB 412-2, which may be local to drilling hub 410-2.

In FIG. 4, respective regions 402 may exhibit the same or similar geological formations. Thus, reference wells, or offset wells, may exist in a vicinity of a given drilling rig 210 in region 402, or where a new well is planned in region 402. Furthermore, multiple drilling rigs 210 may be actively drilling concurrently in region 402, and may be in different stages of drilling through the depths of formation strata layers at region 402. Thus, for any given well being drilled by drilling rig 210 in a region 402, survey data from the reference wells or offset wells may be used to create the well plan, and may be used for surface steering, as disclosed herein. In some implementations, survey data or reference data from a plurality of reference wells may be used to improve drilling performance, such as by reducing an error in estimating TVD or a position of BHA 149 relative to one or more strata layers, as will be described in further detail herein. Additionally, survey data from recently drilled wells, or wells still currently being drilled, including the same well, may be used for reducing an error in estimating TVD or a position of BHA 149 relative to one or more strata layers.

Also shown in FIG. 4 is central command 414, which has access to central drilling DB 416, and may be located at a centralized command center that is in communication with drilling hubs 410 and drilling rigs 210 in various regions 402. The centralized command center may have the ability to monitor drilling and equipment activity at any one or more drilling rigs 210. In some embodiments, central command 414 and drilling hubs 412 may be operated by a commercial operator of drilling rigs 210 as a service to customers who have hired the commercial operator to drill wells and provide other drilling-related services.

In FIG. 4, it is particularly noted that central drilling DB 416 may be a central repository that is accessible to drilling hubs 410 and drilling rigs 210. Accordingly, central drilling DB 416 may store information for various drilling rigs 210 in different regions 402. In some embodiments, central drilling DB 416 may serve as a backup for at least one regional drilling DB 412, or may otherwise redundantly store information that is also stored on at least one regional drilling DB 412. In turn, regional drilling DB 412 may serve as a backup or redundant storage for at least one drilling rig 210 in region 402. For example, regional drilling DB 412 may store information collected by steering control system 168 from drilling rig 210.

In some embodiments, the formulation of a drilling plan for drilling rig 210 may include processing and analyzing the collected data in regional drilling DB 412 to create a more effective drilling plan. Furthermore, once the drilling has begun, the collected data may be used in conjunction with current data from drilling rig 210 to improve drilling decisions. As noted, the functionality of steering control system 168 may be provided at drilling rig 210, or may be provided, at least in part, at a remote processing resource, such as drilling hub 410 or central command 414.

As noted, steering control system 168 may provide functionality as a surface steerable system for controlling drilling rig 210. Steering control system 168 may have access to regional drilling DB 412 and central drilling DB 416 to provide the surface steerable system functionality. As will be described in greater detail below, steering control system 168 may be used to plan and control drilling operations based on input information, including feedback from the drilling process itself. Steering control system 168 may be used to perform operations such as receiving drilling data representing a drill trajectory and other drilling parameters, calculating a drilling solution for the drill trajectory based on the received data and other available data (e.g., rig characteristics), implementing the drilling solution at drilling rig 210, monitoring the drilling process to gauge whether the drilling process is within a margin of error that is defined for the drill trajectory, or calculating corrections for the drilling process if the drilling process is outside of the margin of error.

Referring now to FIG. 5, an example of rig control systems 500 is illustrated in schematic form. It is noted that rig control systems 500 may include fewer or more elements than shown in FIG. 5 in different embodiments. As shown, rig control systems 500 includes steering control system 168 and drilling rig 210. Specifically, steering control system 168 is shown with logical functionality including an autodriller 510, a bit guidance 512, and an autoslide 514. Drilling rig 210 is hierarchically shown including rig controls 520, which provide secure control logic and processing capability, along with drilling equipment 530, which represents the physical equipment used for drilling at drilling rig 210. As shown, rig controls 520 include WOB/differential pressure control system 522, positional/rotary control system 524, fluid circulation control system 526, and sensor system 528, while drilling equipment 530 includes a draw works/snub 532, top drive 140, a mud pumping 536, and an MWD/wireline 538.

Steering control system 168 represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in FIG. 10. Also, WOB/differential pressure control system 522, positional/rotary control system 524, and fluid circulation control system 526 may each represent an instance of a processor having an accessible memory storing instructions executable by the processor, such as an instance of controller 1000 shown in FIG. 10, but for example, in a configuration as a programmable logic controller (PLC) that may not include a user interface but may be used as an embedded controller. Accordingly, it is noted that each of the systems included in rig controls 520 may be a separate controller, such as a PLC, and may autonomously operate, at least to a degree. Steering control system 168 may represent hardware that executes instructions to implement a surface steerable system that provides feedback and automation capability to an operator, such as a driller. For example, steering control system 168 may cause autodriller 510, bit guidance 512 (also referred to as a bit guidance system (BGS)), and autoslide 514 (among others, not shown) to be activated and executed at an appropriate time during drilling. In particular implementations, steering control system 168 may be enabled to provide a user interface during drilling, such as the user interface 850 depicted and described below with respect to FIG. 8. Accordingly, steering control system 168 may interface with rig controls 520 to facilitate manual, assisted manual, semi-automatic, and automatic operation of drilling equipment 530 included in drilling rig 210. It is noted that rig controls 520 may also accordingly be enabled for manual or user-controlled operation of drilling, and may include certain levels of automation with respect to drilling equipment 530.

As shown in FIG. 5, an RSS control system 540 may be provided. The RSS control system 540 is shown as independent of the steering control system 168. It is expected that, in many situations, the RSS control system 540 will be included in the RSS tool and will be downhole in the wellbore being drilled, while control system 168 will be located as a surface location (or at multiple surface locations). However, it should be noted that the RSS control system 540 may be integrated with and/or included in the steering control system 168 if desired and as described below.

In rig control systems 500 of FIG. 5, WOB/differential pressure control system 522 may be interfaced with draw works/snubbing unit 532 to control WOB of drill string 146. Positional/rotary control system 524 may be interfaced with top drive 140 to control rotation of drill string 146. Fluid circulation control system 526 may be interfaced with mud pumping 536 to control mud flow and may also receive and decode mud telemetry signals. Sensor system 528 may be interfaced with MWD/wireline 538, which may represent various BHA sensors and instrumentation equipment, among other sensors that may be downhole or at the surface.

In rig control systems 500, autodriller 510 may represent an automated rotary drilling system and may be used for controlling rotary drilling. Accordingly, autodriller 510 may enable automate operation of rig controls 520 during rotary drilling, as indicated in the well plan. Bit guidance 512 may represent an automated control system to monitor and control performance and operation drilling bit 148.

In rig control systems 500, autoslide 514 may represent an automated slide drilling system and may be used for controlling slide drilling. Accordingly, autoslide 514 may enable automate operation of rig controls 520 during a slide, and may return control to steering control system 168 for rotary drilling at an appropriate time, as indicated in the well plan. In particular implementations, autoslide 514 may be enabled to provide a user interface during slide drilling to specifically monitor and control the slide. For example, autoslide 514 may rely on bit guidance 512 for orienting a tool face and on autodriller 510 to set WOB or control rotation or vibration of drill string 146.

FIG. 6 illustrates one embodiment of control algorithm modules 600 used with steering control system 168. The control algorithm modules 600 of FIG. 6 include: a slide control executor 650 that is responsible for managing the execution of the slide control algorithms; a slide control configuration provider 652 that is responsible for validating, maintaining, and providing configuration parameters for the other software modules; a BHA & pipe specification provider 654 that is responsible for managing and providing details of BHA 149 and drill string 146 characteristics; a borehole geometry model 656 that is responsible for keeping track of the borehole geometry and providing a representation to other software modules; a top drive orientation impact model 658 that is responsible for modeling the impact that changes to the angular orientation of top drive 140 have had on the tool face control; a top drive oscillator impact model 660 that is responsible for modeling the impact that oscillations of top drive 140 has had on the tool face control; an ROP impact model 662 that is responsible for modeling the effect on the tool face control of a change in ROP or a corresponding ROP set point; a WOB impact model 664 that is responsible for modeling the effect on the tool face control of a change in WOB or a corresponding WOB set point; a differential pressure impact model 666 that is responsible for modeling the effect on the tool face control of a change in differential pressure (DP) or a corresponding DP set point; a torque model 668 that is responsible for modeling the comprehensive representation of torque for surface, downhole, break over, and reactive torque, modeling impact of those torque values on tool face control, and determining torque operational thresholds; a tool face control evaluator 672 that is responsible for evaluating all factors impacting tool face control and whether adjustments need to be projected, determining whether re-alignment off-bottom is indicated, and determining off-bottom tool face operational threshold windows; a tool face projection 670 that is responsible for projecting tool face behavior for top drive 140, the top drive oscillator, and auto driller adjustments; a top drive adjustment calculator 674 that is responsible for calculating top drive adjustments resultant to tool face projections; an oscillator adjustment calculator 676 that is responsible for calculating oscillator adjustments resultant to tool face projections; and an autodriller adjustment calculator 678 that is responsible for calculating adjustments to autodriller 510 resultant to tool face projections.

FIG. 7 illustrates one embodiment of a steering control process 700 for determining a corrective action for drilling. Steering control process 700 may be used for rotary drilling or slide drilling in different embodiments.

Steering control process 700 in FIG. 7 illustrates a variety of inputs that can be used to determine an optimum corrective action. As shown in FIG. 7, the inputs include formation hardness/unconfined compressive strength (UCS) 710, formation structure 712, inclination/azimuth 714, current zone 716, measured depth 718, desired tool face 730, vertical section 720, bit factor 722, mud motor torque 724, reference trajectory 730, vertical section 720, bit factor 722, torque 724 and angular velocity 726. In FIG. 7, reference trajectory 730 of borehole 106 is determined to calculate a trajectory misfit in a step 732. Step 732 may output the trajectory misfit to determine a corrective action to minimize the misfit at step 734, which may be performed using the other inputs described above. Then, at step 736, the drilling rig is caused to perform the corrective action.

It is noted that in some implementations, at least certain portions of steering control process 700 may be automated or performed without user intervention, such as using rig control systems 700 (see FIG. 7). In other implementations, the corrective action in step 736 may be provided or communicated (by display, SMS message, email, or otherwise) to one or more human operators, who may then take appropriate action. The human operators may be members of a rig crew, which may be located at or near drilling rig 210, or may be located remotely from drilling rig 210.

Referring to FIG. 8, one embodiment of a user interface 850 that may be generated by steering control system 168 for monitoring and operation by a human operator is illustrated. User interface 850 may provide many different types of information in an easily accessible format. For example, user interface 850 may be shown on a computer monitor, a television, a viewing screen (e.g., a display device) associated with steering control system 168.

As shown in FIG. 8, user interface 850 provides visual indicators such as a hole depth indicator 852, a bit depth indicator 854, a GAMMA indicator 856, an inclination indicator 858, an azimuth indicator 860, and a TVD indicator 862. Other indicators may also be provided, including a ROP indicator 864, a mechanical specific energy (MSE) indicator 866, a differential pressure indicator 868, a standpipe pressure indicator 870, a flow rate indicator 872, a rotary RPM (angular velocity) indicator 874, a bit speed indicator 876, and a WOB indicator 878.

In FIG. 8, at least some of indicators 864, 866, 868, 870, 872, 874, 876, and 878 may include a marker representing a target value. For example, markers may be set as certain given values, but it is noted that any desired target value may be used. Although not shown, in some embodiments, multiple markers may be present on a single indicator. The markers may vary in color or size. For example, ROP indicator 864 may include a marker 865 indicating that the target value is 50 feet/hour (or 15 m/h). MSE indicator 866 may include a marker 867 indicating that the target value is 37 ksi (or 255 MPa). Differential pressure indicator 868 may include a marker 869 indicating that the target value is 200 psi (or 1.38 kPa). ROP indicator 864 may include a marker 865 indicating that the target value is 50 feet/hour (or 15 m/h). Standpipe pressure indicator 870 may have no marker in the present example. Flow rate indicator 872 may include a marker 873 indicating that the target value is 500 gpm (or 31.5 L/s). Rotary RPM indicator 874 may include a marker 875 indicating that the target value is 0 RPM (e.g., due to sliding). Bit speed indicator 876 may include a marker 877 indicating that the target value is 150 RPM. WOB indicator 878 may include a marker 879 indicating that the target value is 10 klbs (or 4,500 kg). Each indicator may also include a colored band, or another marking, to indicate, for example, whether the respective gauge value is within a safe range (e.g., indicated by a green color), within a caution range (e.g., indicated by a yellow color), or within a danger range (e.g., indicated by a red color).

In FIG. 8, a log chart 880 may visually indicate depth versus one or more measurements (e.g., may represent log inputs relative to a progressing depth chart). For example, log chart 880 may have a Y-axis representing depth and an X-axis representing a measurement such as GAMMA count 881 (as shown), ROP 883 (e.g., empirical ROP and normalized ROP), or resistivity. An autopilot button 882 and an oscillate button 884 may be used to control activity. For example, autopilot button 882 may be used to engage or disengage autodriller 510, while oscillate button 884 may be used to directly control oscillation of drill string 146 or to engage/disengage an external hardware device or controller.

In FIG. 8, a circular chart 886 may provide current and historical tool face orientation information (e.g., which way the bend is pointed). For purposes of illustration, circular chart 886 represents three hundred and sixty degrees. A series of circles within circular chart 886 may represent a timeline of tool face orientations, with the sizes of the circles indicating the temporal position of each circle. For example, larger circles may be more recent than smaller circles, so a largest circle 888 may be the newest reading and a smallest circle 889 may be the oldest reading. In other embodiments, circles 889, 888 may represent the energy or progress made via size, color, shape, a number within a circle, etc. For example, a size of a particular circle may represent an accumulation of orientation and progress for the period of time represented by the circle. In other embodiments, concentric circles representing time (e.g., with the outside of circular chart 886 being the most recent time and the center point being the oldest time) may be used to indicate the energy or progress (e.g., via color or patterning such as dashes or dots rather than a solid line).

In user interface 850, circular chart 886 may also be color coded, with the color coding existing in a band 890 around circular chart 886 or positioned or represented in other ways. The color coding may use colors to indicate activity in a certain direction. For example, the color red may indicate the highest level of activity, while the color blue may indicate the lowest level of activity. Furthermore, the arc range in degrees of a color may indicate the amount of deviation. Accordingly, a relatively narrow (e.g., thirty degrees) arc of red with a relatively broad (e.g., three hundred degrees) arc of blue may indicate that most activity is occurring in a particular tool face orientation with little deviation. As shown in user interface 850, the color blue may extend from approximately 22-337 degrees, the color green may extend from approximately 15-22 degrees and 337-345 degrees, the color yellow may extend a few degrees around the 13 and 345 degree marks, while the color red may extend from approximately 347-10 degrees. Transition colors or shades may be used with, for example, the color orange marking the transition between red and yellow or a light blue marking the transition between blue and green. This color coding may enable user interface 850 to provide an intuitive summary of how narrow the standard deviation is and how much of the energy intensity is being expended in the proper direction. Furthermore, the center of energy may be viewed relative to the target. For example, user interface 850 may clearly show that the target is at 90 degrees but the center of energy is at 45 degrees.

In user interface 850, other indicators, such as a slide indicator 892, may indicate how much time remains until a slide occurs or how much time remains for a current slide. For example, slide indicator 892 may represent a time, a percentage (e.g., as shown, a current slide may be 56% complete), a distance completed, or a distance remaining. Slide indicator 892 may graphically display information using, for example, a colored bar 893 that increases or decreases with slide progress. In some embodiments, slide indicator 892 may be built into circular chart 886 (e.g., around the outer edge with an increasing/decreasing band), while in other embodiments slide indicator 892 may be a separate indicator such as a meter, a bar, a gauge, or another indicator type. In various implementations, slide indicator 892 may be refreshed by autoslide 514.

In user interface 850, an error indicator 894 may indicate a magnitude and a direction of error. For example, error indicator 894 may indicate that an estimated drill bit position is a certain distance from the planned trajectory, with a location of error indicator 894 around the circular chart 886 representing the heading. For example, FIG. 8 illustrates an error magnitude of 15 feet and an error direction of 15 degrees. Error indicator 894 may be any color but may be red for purposes of example. It is noted that error indicator 894 may present a zero if there is no error. Error indicator may represent that drill bit 148 is on the planned trajectory using other means, such as being a green color. Transition colors, such as yellow, may be used to indicate varying amounts of error. In some embodiments, error indicator 894 may not appear unless there is an error in magnitude or direction. A marker 896 may indicate an ideal slide direction. Although not shown, other indicators may be present, such as a bit life indicator to indicate an estimated lifetime for the current bit based on a value such as time or distance.

It is noted that user interface 850 may be arranged in many different ways. For example, colors may be used to indicate normal operation, warnings, and problems. In such cases, the numerical indicators may display numbers in one color (e.g., green) for normal operation, may use another color (e.g., yellow) for warnings, and may use yet another color (e.g., red) when a serious problem occurs. The indicators may also flash or otherwise indicate an alert. The gauge indicators may include colors (e.g., green, yellow, and red) to indicate operational conditions and may also indicate the target value (e.g., an ROP of 100 feet/hour). For example, ROP indicator 868 may have a green bar to indicate a normal level of operation (e.g., from 10-300 feet/hour), a yellow bar to indicate a warning level of operation (e.g., from 300-360 feet/hour), and a red bar to indicate a dangerous or otherwise out of parameter level of operation (e.g., from 360-390 feet/hour). ROP indicator 868 may also display a marker at 100 feet/hour to indicate the desired target ROP.

Furthermore, the use of numeric indicators, gauges, and similar visual display indicators may be varied based on factors such as the information to be conveyed and the personal preference of the viewer. Accordingly, user interface 850 may provide a customizable view of various drilling processes and information for a particular individual involved in the drilling process. For example, steering control system 168 may enable a user to customize the user interface 850 as desired, although certain features (e.g., standpipe pressure) may be locked to prevent a user from intentionally or accidentally removing important drilling information from user interface 850. Other features and attributes of user interface 850 may be set by user preference. Accordingly, the level of customization and the information shown by the user interface 850 may be controlled based on who is viewing user interface 850 and their role in the drilling process.

Referring to FIG. 9, one embodiment of a guidance control loop (GCL) 900 is shown in further detail CL 900 may represent one example of a control loop or control algorithm executed under the control of steering control system 168. GCL 900 may include various functional modules, including a build rate predictor 902, a geo modified well planner 904, a borehole estimator 906, a slide estimator 908, an error vector calculator 910, a geological drift estimator 912, a slide planner 914, a convergence planner 916, and a tactical solution planner 918. In the following description of GCL 900, the term “external input” refers to input received from outside GCL 900, while “internal input” refers to input exchanged between functional modules of GCL 900.

In FIG. 9, build rate predictor 902 receives external input representing BHA information and geological information, receives internal input from the borehole estimator 906, and provides output to geo modified well planner 904, slide estimator 908, slide planner 914, and convergence planner 916. Build rate predictor 902 is configured to use the BHA information and geological information to predict drilling build rates of current and future sections of borehole 106. For example, build rate predictor 902 may determine how aggressively a curve will be built for a given formation with BHA 149 and other equipment parameters.

In FIG. 9, build rate predictor 902 may use the orientation of BHA 149 to the formation to determine an angle of attack for formation transitions and build rates within a single layer of a formation. For example, if a strata layer of rock is below a strata layer of sand, a formation transition exists between the strata layer of sand and the strata layer of rock. Approaching the strata layer of rock at a 90 degree angle may provide a good tool face and a clean drill entry, while approaching the rock layer at a 45 degree angle may build a curve relatively quickly. An angle of approach that is near parallel may cause drill bit 148 to skip off the upper surface of the strata layer of rock. Accordingly, build rate predictor 902 may calculate BHA orientation to account for formation transitions. Within a single strata layer, build rate predictor 902 may use the BHA orientation to account for internal layer characteristics (e.g., grain) to determine build rates for different parts of a strata layer. The BHA information may include bit characteristics, mud motor bend setting, stabilization and mud motor bit to bend distance. The geological information may include formation data such as compressive strength, thicknesses, and depths for formations encountered in the specific drilling location. Such information may enable a calculation-based prediction of the build rates and ROP that may be compared to both results obtained while drilling borehole 106 and regional historical results (e.g., from the regional drilling DB 412) to improve the accuracy of predictions as drilling progresses. Build rate predictor 902 may also be used to plan convergence adjustments and confirm in advance of drilling that targets can be achieved with current parameters.

In FIG. 9, geo modified well planner 904 receives external input representing a well plan, internal input from build rate predictor 902 and geo drift estimator 912, and provides output to slide planner 914 and error vector calculator 910. Geo modified well planner 904 uses the input to determine whether there is a more desirable trajectory than that provided by the well plan, while staying within specified error limits. More specifically, geo modified well planner 904 takes geological information (e.g., drift) and calculates whether another trajectory solution to the target may be more efficient in terms of cost or reliability. The outputs of geo modified well planner 904 to slide planner 914 and error vector calculator 910 may be used to calculate an error vector based on the current vector to the newly calculated trajectory and to modify slide predictions. In some embodiments, go modified well planner 904 (or another module) may provide functionality needed to track a formation trend. For example, in horizontal wells, a geologist may provide steering control system 168 with a target inclination as a set point for steering control system 168 to control. For example, the geologist may enter a target to steering control system 168 of 90.5-91.0 degrees of inclination for a section of borehole 106. Geo modified well planner 904 may then treat the target as a vector target, while remaining within the error limits of the original well plan. In some embodiments, geo modified well planner 904 may be an optional module that is not used unless the well plan is to be modified. For example, if the well plan is marked in steering control system 168 as non-modifiable, geo modified well planner 904 may be bypassed altogether or geo modified well planner 904 may be configured to pass the well plan through without any changes.

In FIG. 9, borehole estimator 906 may receive external inputs representing BHA information, measured depth information, survey information (e.g., azimuth and inclination), and may provide outputs to build rate predictor 902, error vector calculator 910, and convergence planner 916. Borehole estimator 906 may be configured to provide an estimate of the actual borehole and drill bit position and trajectory angle without delay, based on either straight line projections or projections that incorporate sliding. Borehole estimator 906 may be used to compensate for a sensor being physically located some distance behind drill bit 148 (e.g., 50 feet) in drill string 146, which makes sensor readings lag the actual bit location by 50 feet. Borehole estimator 906 may also be used to compensate for sensor measurements that may not be continuous (e.g., a sensor measurement may occur every 100 feet). Borehole estimator 906 may provide the most accurate estimate from the surface to the last survey location based on the collection of survey measurements. Also, borehole estimator 906 may take the slide estimate from slide estimator 908 (described below) and extend the slide estimate from the last survey point to a current location of drill bit 148. Using the combination of these two estimates, borehole estimator 906 may provide steering control system 168 with an estimate of the drill bit's location and trajectory angle from which guidance and steering solutions can be derived. An additional metric that can be derived from the borehole estimate is the effective build rate that is achieved throughout the drilling process.

In FIG. 9, slide estimator 908 receives external inputs representing measured depth and differential pressure information, receives internal input from build rate predictor 902, and provides output to borehole estimator 906 and geo modified well planner 904. Slide estimator 908 may be configured to sample tool face orientation, differential pressure, measured depth (MD) incremental movement, MSE, and other sensor feedback to quantity/estimate a deviation vector and progress while sliding.

Traditionally, deviation from the slide would be predicted by a human operator based on experience. The operator would, for example, use a long slide cycle to assess what likely was accomplished during the last slide. However, the results are generally not confirmed until the downhole survey sensor point passes the slide portion of the borehole, often resulting in a response lag defined by a distance of the sensor point from the drill bit tip (e.g., approximately 50 feet). Such a response lag may introduce inefficiencies in the slide cycles due to over/under correction of the actual trajectory relative to the planned trajectory.

In GCL 900, using slide estimator 908, each tool face update may be algorithmically merged with the average differential pressure of the period between the previous and current tool face readings, as well as the MD change during this period to predict the direction, angular deviation, and MD progress during the period. As an example, the periodic rate may be between 10 and 60 seconds per cycle depending on the tool face update rate of downhole tool 166. With a more accurate estimation of the slide effectiveness, the sliding efficiency can be improved. The output of slide estimator 908 may accordingly be periodically provided to borehole estimator 906 for accumulation of well deviation information, as well to geo modified well planner 904. Some or all of the output of the slide estimator 908 may be output to an operator, such as shown in the user interface 850 of FIG. 8.

In FIG. 9, error vector calculator 910 may receive internal input from geo modified well planner 904 and borehole estimator 906. Error vector calculator 910 may be configured to compare the planned well trajectory to an actual borehole trajectory and drill bit position estimate. Error vector calculator 910 may provide the metrics used to determine the error (e.g., how far off) the current drill bit position and trajectory are from the well plan. For example, error vector calculator 910 may calculate the error between the current bit position and trajectory to the planned trajectory and the desired bit position. Error vector calculator 910 may also calculate a projected bit position/projected trajectory representing the future result of a current error.

In FIG. 9, geological drift estimator 912 receives external input representing geological information and provides outputs to geo modified well planner 904, slide planner 914, and tactical solution planner 918. During drilling, drift may occur as the particular characteristics of the formation affect the drilling direction. More specifically, there may be a trajectory bias that is contributed by the formation as a function of ROP and BHA 149. Geological drift estimator 912 is configured to provide a drift estimate as a vector that can then be used to calculate drift compensation parameters that can be used to offset the drift in a control solution.

In FIG. 9, slide planner 914 receives internal input from build rate predictor 902, geo modified well planner 904, error vector calculator 910, and geological drift estimator 912, and provides output to convergence planner 916 as well as an estimated time to the next slide. Slide planner 914 may be configured to evaluate a slide/drill ahead cost calculation and plan for sliding activity, which may include factoring in BHA wear, expected build rates of current and expected formations, and the well plan trajectory. During drill ahead, slide planner 914 may attempt to forecast an estimated time of the next slide to aid with planning. For example, if additional lubricants (e.g., fluorinated beads) are indicated for the next slide, and pumping the lubricants into drill string 146 has a lead time of 30 minutes before the slide, the estimated time of the next slide may be calculated and then used to schedule when to start pumping the lubricants. Functionality for a loss circulation material (LCM) planner may be provided as part of slide planner 914 or elsewhere (e.g., as a stand-alone module or as part of another module described herein). The LCM planner functionality may be configured to determine whether additives should be pumped into the borehole based on indications such as flow-in versus flow-back measurements. For example, if drilling through a porous rock formation, fluid being pumped into the borehole may get lost in the rock formation. To address this issue, the LCM planner may control pumping LCM into the borehole to clog up the holes in the porous rock surrounding the borehole to establish a more closed-loop control system for the fluid.

In FIG. 9, slide planner 914 may also look at the current position relative to the next connection. A connection may happen every 90 to 100 feet (or some other distance or distance range based on the particulars of the drilling operation) and slide planner 914 may avoid planning a slide when close to a connection or when the slide would carry through the connection. For example, if the slide planner 914 is planning a 50 foot slide but only 20 feet remain until the next connection, slide planner 914 may calculate the slide starting after the next connection and make any changes to the slide parameters to accommodate waiting to slide until after the next connection. Such flexible implementation avoids inefficiencies that may be caused by starting the slide, stopping for the connection, and then having to reorient the tool face before finishing the slide. During slides, slide planner 914 may provide some feedback as to the progress of achieving the desired goal of the current slide. In some embodiments, slide planner 914 may account for reactive torque in the drill string. More specifically, when rotating is occurring, there is a reactional torque wind up in drill string 146. When the rotating is stopped, drill string 146 unwinds, which changes tool face orientation and other parameters. When rotating is started again, drill string 146 starts to wind back up. Slide planner 914 may account for the reactional torque so that tool face references are maintained, rather than stopping rotation and then trying to adjust to a desired tool face orientation. While not all downhole tools may provide tool face orientation when rotating, using one that does supply such information for GCL 900 may significantly reduce the transition time from rotating to sliding.

In FIG. 9, convergence planner 916 receives internal inputs from build rate predictor 902, borehole estimator 906, and slide planner 914, and provides output to tactical solution planner 918. Convergence planner 916 is configured to provide a convergence plan when the current drill bit position is not within a defined margin of error of the planned well trajectory. The convergence plan represents a path from the current drill bit position to an achievable and desired convergence target point along the planned trajectory. The convergence plan may take account the amount of sliding/drilling ahead that has been planned to take place by slide planner 914. Convergence planner 916 may also use BHA orientation information for angle of attack calculations when determining convergence plans as described above with respect to build rate predictor 902. The solution provided by convergence planner 916 defines a new trajectory solution for the current position of drill bit 148. The solution may be immediate without delay, or planned for implementation at a future time that is specified in advance.

In FIG. 9, tactical solution planner 918 receives internal inputs from geological drift estimator 912 and convergence planner 916, and provides external outputs representing information such as tool face orientation, differential pressure, and mud flow rate. Tactical solution planner 918 is configured to take the trajectory solution provided by convergence planner 916 and translate the solution into control parameters that can be used to control drilling rig 210. For example, tactical solution planner 918 may convert the solution into settings for control systems 522, 524, and 526 to accomplish the actual drilling based on the solution. Tactical solution planner 918 may also perform performance optimization to optimizing the overall drilling operation as well as optimizing the drilling itself (e.g., how to drill faster).

Other functionality may be provided by GCL 900 in additional modules or added to an existing module. For example, there is a relationship between the rotational position of the drill pipe on the surface and the orientation of the downhole tool face. Accordingly, GCL 900 may receive information corresponding to the rotational position of the drill pipe on the surface. GCL 900 may use this surface positional information to calculate current and desired tool face orientations. These calculations may then be used to define control parameters for adjusting the top drive 140 to accomplish adjustments to the downhole tool face in order to steer the trajectory of borehole 106.

For purposes of example, an object-oriented software approach may be utilized to provide a class-based structure that may be used with GCL 900 or other functionality provided by steering control system 168. In GCL 900, a drilling model class may be defined to capture and define the drilling state throughout the drilling process. The drilling model class may include information obtained without delay. The drilling model class may be based on the following components and sub-models: a drill bit model, a borehole model, a rig surface gear model, a mud pump model, a WOB/differential pressure model, a positional/rotary model, an MSE model, an active well plan, and control limits. The drilling model class may produce a control output solution and may be executed via a main processing loop that rotates through the various modules of GCL 900. The drill bit model may represent the current position and state of drill bit 148. The drill bit model may include a three dimensional (3D) position, a drill bit trajectory, BHA information, bit speed, and tool face (e.g., orientation information). The 3D position may be specified in north-south (NS), east-west (EW), and true vertical depth (TVD). The drill bit trajectory may be specified as an inclination angle and an azimuth angle. The BHA information may be a set of dimensions defining the active BHA. The borehole model may represent the current path and size of the active borehole. The borehole model may include hole depth information, an array of survey points collected along the borehole path, a gamma log, and borehole diameters. The hole depth information is for current drilling of borehole 106. The borehole diameters may represent the diameters of borehole 106 as drilled over current drilling. The rig surface gear model may represent pipe length, block height, and other models, such as the mud pump model, WOB/differential pressure model, positional/rotary model, and MSE model. The mud pump model represents mud pump equipment and includes flow rate, standpipe pressure, and differential pressure. The WOB/differential pressure model represents draw works or other WOB/differential pressure controls and parameters, including WOB. The positional/rotary model represents top drive or other positional/rotary controls and parameters including rotary RPM and spindle position. The active well plan represents the target borehole path and may include an external well plan and a modified well plan. The control limits represent defined parameters that may be set as maximums and/or minimums. For example, control limits may be set for the rotary RPM in the top drive model to limit the maximum RPMs to the defined level. The control output solution may represent the control parameters for drilling rig 210.

Each functional module of GCL 900 may have behavior encapsulated within a respective class definition. During a processing window, the individual functional modules may have an exclusive portion in time to execute and update the drilling model. For purposes of example, the processing order for the functional modules may be in the sequence of geo modified well planner 904, build rate predictor 902, slide estimator 908, borehole estimator 906, error vector calculator 910, slide planner 914, convergence planner 916, geological drift estimator 912, and tactical solution planner 918. It is noted that other sequences may be used in different implementations.

In FIG. 9, GCL 900 may rely on a programmable timer module that provides a timing mechanism to provide timer event signals to drive the main processing loop. While steering control system 168 may rely on timer and date calls driven by the programming environment, timing may be obtained from other sources than system time. In situations where it may be advantageous to manipulate the clock (e.g., for evaluation and testing), a programmable timer module may be used to alter the system time. For example, the programmable timer module may enable a default time set to the system time and a time scale of 1.0, may enable the system time of steering control system 168 to be manually set, may enable the time scale relative to the system time to be modified, or may enable periodic event time requests scaled to a requested time scale.

Referring now to FIG. 10, a block diagram illustrating selected elements of an embodiment of a controller 1000 for performing surface steering according to the present disclosure. In various embodiments, controller 1000 may represent an implementation of steering control system 168. In other embodiments, at least certain portions of controller 1000 may be used for control systems 510, 512, 514, 522, 524, and 526 (see FIG. 5).

In the embodiment depicted in FIG. 10, controller 1000 includes processor 1001 coupled via shared bus 1002 to storage media collectively identified as memory media 1010.

Controller 1000, as depicted in FIG. 10, further includes network adapter 1020 that interfaces controller 1000 to a network (not shown in FIG. 10). In embodiments suitable for use with user interfaces, controller 1000, as depicted in FIG. 10, may include peripheral adapter 1006, which provides connectivity for the use of input device 1008 and output device 1009. Input device 1008 may represent a device for user input, such as a keyboard or a mouse, or even a video camera. Output device 1009 may represent a device for providing signals or indications to a user, such as loudspeakers for generating audio signals.

Controller 1000 is shown in FIG. 10 including display adapter 1004 and further includes a display device 1005. Display adapter 1004 may interface shared bus 1002, or another bus, with an output port for one or more display devices, such as display device 1005. Display device 1005 may be implemented as a liquid crystal display screen, a computer monitor, a television or the like. Display device 1005 may comply with a display standard for the corresponding type of display. Standards for computer monitors include analog standards such as video graphics array (VGA), extended graphics array (XGA), etc., or digital standards such as digital visual interface (DVI), definition multimedia interface (HDMI), among others. A television display may comply with standards such as NTSC (National Television System Committee), PAL (Phase Alternating Line), or another suitable standard. Display device 1005 may include an output device 1009, such as one or more integrated speakers to play audio content, or may include an input device 1008, such as a microphone or video camera.

In FIG. 10, memory media 1010 encompasses persistent and volatile media, fixed and removable media, and magnetic and semiconductor media. Memory media 1010 is operable to store instructions, data, or both. Memory media 1010 as shown includes sets or sequences of instructions 1024-2, namely, an operating system 1012 and surface steering control 1014. Operating system 1012 may be a UNIX or UNIX-like operating system, a Windows) family operating system, or another suitable operating system. Instructions 1024 may also reside, completely or at least partially, within processor 1001 during execution thereof. It is further noted that processor 1001 may be configured to receive instructions 1024-1 from instructions 1024-2 via shared bus 1002. In some embodiments, memory media 1010 is configured to store and provide executable instructions for executing GCL 900, as mentioned previously, among other methods and operations disclosed herein.

In addition to the drilling systems and methods described previously, rotary steerable systems (RSS), also referred to as rotary steerable tools, may be used with BHA 149 for drilling borehole 106. As used herein, “rotary steerable” with regard to drilling borehole 106 refers to the ability to maintain a fixed angular offset of drill bit 148 with respect to a rotational axis of drill string 146 while drill string 146 is being rotated by top drive 140. Accordingly, BHA 149 may represent a rotary steerable BHA, or a BHA including an RSS, as described herein. Such rotary steerable functionality includes what is sometimes referred to as “point-the-bit” rotary drilling. The angular offset can be maintained relative to the formation being drilled through (geostationary drill bit positioning) and can enable the use of rotary steering to define a desired trajectory of borehole 106 by enabling curved drilling. In contrast with slide drilling, as explained previously, in which drill string 146 is not rotated and a mud motor is used to turn drill bit 148, an RSS may be used to increase the rotational velocity of drill bit 148 by using the mud motor while drill string 146 is also rotated.

In order to drill a curved trajectory of borehole 106 using an RSS, depending on the formation and desired drilling parameters, the angular offset can be maintained at a non-zero geostationary value in order to drill at the angular offset. The drilling of a curved wellbore using an RSS can be accomplished using direct drive of drill bit 148 by BHA 149 or by using a mud motor with BHA 149 to drive drill bit 148, as will be explained in further detail.

In order to drill a straight wellbore using an RSS, the angular offset may be set to zero or may be held fixed while drill bit 148 is rotated. In this case, the angular offset also rotates and is not held geostationary. When the angular offset is greater than zero and is held fixed, BHA 149 is equivalent to a bent sub, and a diameter of the drilled borehole when drilled straight will be increased.

During drilling operations, certain reactive loads placed on rotary steerable tools used for drilling with drill bit 148 can cause harmful vibrational loads that can cause adverse mechanical effects along drill string 146, including causing certain equipment to prematurely fail or causing excessive wear rates that can reduce equipment service life. In some cases, the harmful vibrational loads can be caused when oscillations caused by the interaction of drill bit 148 with borehole 106 are associated with resonant frequencies of drill bit 148, BHA 149, drill string 146, or other equipment, which can cause the oscillations to be amplified in magnitude. In some cases, the harmful vibrational loads can be caused by drill bit 148 continuously sticking and springing forward (e.g., a stick-slip condition) that can cause damage as the torsional strain of drill string 146 unwinds in an uncontrolled manner.

The system and method for optimizing drilling with a rotary steerable system, as disclosed herein, may vary or fine tune a rotational speed of drill bit 148, which may be associated with an independently controlled rotational speed within BHA 149. In this manner, the system and method for optimizing drilling with a rotary steerable system, as disclosed herein, may alter a depth of cut of cutting elements of drill bit 148, in order to alter a size of a bite taken by drill bit 148 when cutting into geological formation 102.

In certain configurations, drill bit 148 may be attached to BHA 149 at a small mechanically fixed angle, also referred to as a “bent sub”. With the use of a bent sub, when drill string 146 is rotated, drill bit 148 also rotates along with the bent sub, but drill bit 148 no longer rotates about the rotational axis of drill string 146. Instead, drill bit 148 rotates about a slightly larger radius defined by the bent sub, which results in straight drilling of borehole 106 nonetheless along the rotational axis of drill string 146. In order to directionally drill using the bent sub, a mud motor is used to rotate drill bit 148 independently of drill string 146, which is held fixed, thereby introducing a curve into the trajectory of borehole 106.

Certain RSS tools (or rotary steerable tools) may have the ability to define an angular offset of drill bit 148 relative to the rotational axis of drill string 146. The angular offset may enable BHA 149 to provide point-the-bit steering in a desired direction that is maintained downhole by the RSS tool. The adjustable offset of such an RSS tool may operate similarly to a universal joint that is fixed at a given angle, and may enable desired redirection of the mechanical rotation of drill string 146 to the axis defined by the angular offset. The angular offset can also be repeatedly or continuously adjusted during a drilling operation, to create a rotation of the angle of drill bit 148 relative to borehole 106. RSS tools in accordance with some embodiments may be capable of rotating the angular offset either clockwise or counterclockwise at speeds in excess of conventional drill string rotation speeds. With this capability, RSS tools may be enabled to alter the interaction of drill bit 148 with the bottom of borehole 106 to improve drilling efficiency and reduce excessive or undesired wear on drill bit 148.

In addition to the adjustable angular offset of drill bit 148, RSS tools may further be equipped with a continuously variable transmission (CVT) that can be used to control rotation of drill bit 148 independently of the rotation of drill string 146. Accordingly, the CVT in the RSS tool can be used to apply a transmission ratio to the output rotation of drill bit 148 with respect to the input rotation of drill string 146 by top drive 140. An RSS tool having such a CVT along with an adjustable angular offset is disclosed in U.S. Pat. No. 7,481,281 to Schauf, which is hereby incorporated by reference in its entirety.

Furthermore, during drilling, reactive loads applied to BHA 149 from borehole 106 and loads applied to drill string 146 from top drive 140 at surface 104 may affect oscillation of drill string 146 and BHA 149. The effect of such oscillations of drill string 146 and BHA 149 may include the introduction of potentially harmful vibrational loads, for example, such as in a resonant frequency range of the downhole equipment being used, which is undesirable. Excessive vibrational loads can lead to damage to drill string 146 and/or components of BHA 149, along with negatively affecting drilling efficiency, which is undesirable. As will be described in further detail, in order to achieve desired performance, such oscillations of drill string 146 and BHA 149 may be monitored and controlled, such that during drilling of borehole 106, the vibrational loads experienced by drill string 146 and BHA 149 remain within desired limits and do not become excessive.

As noted previously, BHA 149 may include suitable sensors for monitoring a condition, a motion, or a vibrational state of drill string 146 during drilling. The sensors may accordingly pick up signals or other indications of the drilling loads applied to drill string 146. The drilling loads monitored in this manner may originate from the surface, such as by top drive 140, or may result from interaction of BHA 149 and drill bit 148 with borehole 106, or both. The sensors enabled to detect such vibrational loads may be gyroscopes, accelerometers, and/or magnetometers and may be incorporated within BHA 149. Accordingly, the sensors can produce measurements of accelerations (axial and lateral to borehole 106) and torsional accelerations of BHA 149 during drilling without delay. Additionally, certain logical or processing capability associated with the sensors may be enabled to correlate the measurements in order to detect certain drilling conditions, such as a stick-slip condition (which may be indicated by a varying or erratic rotational speed of drill bit 148), a harmonic vibration in drill string 146 or BHA 149 (which may be indicated by increasing lateral accelerations of BHA 149), as well as another unexpected or undesirable drilling condition. In some embodiments, the sensors may include a microelectromechanical system (MEMS) component, such as a MEMS gyroscope or a MEMS accelerometer. In some embodiments, MEMS sensors can provide more accurate and precise measurements of angular accelerations compared to alternative technologies, such as ring laser gyroscopes, fiber optic gyroscopes, rotating mass gyroscopes, or inertial navigation units, among others, which may also be used with BHA 149 for rotary steerable functionality, as disclosed herein.

In addition to sensors for detecting drilling loads and vibrations without delay, BHA 149 may further include processing or logic capability to analyze the measurements detected by the sensors, and to make a determination whether the measured values and signals indicate harmful vibrational loads in drill string 146. For example, in this manner, when a drilling problem is detected, BHA 149 can be programmed to generate a control indication for adjusting a rotational speed (e.g., adjusting angular velocity) of drill bit 148 or of reversing an angular direction of rotation of drill bit 148. Then, depending on how the rotation of drill bit 148 is being controlled, as will be explained in further detail below, BHA 149 or surface steerable system 168 may be enabled to cause the control indication to be implemented. For example, the control indication may be an increase or a decrease in the rotational speed of drill bit 148, which may be independent of the rotational speed of top drive 140, to minimize stick-slip or reduce vibrational loads. In some embodiments, if a drilling problem improves in response to the control indication, BHA 149 (or surface steerable system 168) may determine that one or more further control indications are warranted and may make a further adjustment. If the drilling problem does not improve or gets worse in response to the control indication, then BHA 149 (or a surface control system, such as surface steerable system 168) may determine that a reversal of the angular rotational direction is warranted, either as a potential action for alleviating the drilling problem, or as a result of adjusting the angular rotational speed of drill bit 148 through zero rotation speed. In some embodiments, BHA 149 (or the surface control system 168) may detect that any adjustment results in insufficient improvement, and may then stop adjusting the rotational speed of drill bit 148. In some embodiments, BHA 149 (or surface steerable system 168) may determine that certain measured values (e.g., vibration, variations in rotational speed associated with stick-slip, vibrational direction, etc.) are within acceptable limits and do not indicate any further adjustments to drilling.

In addition to sensors for detecting drilling loads and vibrations without delay, BHA 149 may further include processing or logic capability to receive, monitor, analyze the measurements detected by the sensors during drilling, and to make a determination whether the measured values from the sensors indicate a geological drift, such as a tendency of the drill bit to drill in a particular direction due to the characteristics of the formation(s) being drilled. In addition, the information from the sensors may be used to determine a directional tendency, such as may result from the combination of drill string 146, BHA 149 and bit 148. For example, in this manner, when such a trend (due to either or both of geological drift and directional tendency due to equipment) is detected, BHA 149 can be programmed to generate a control response adjusting the angular rotation speed (i.e., angular velocity) of drill bit 148 or adjusting (e.g., reversing) an angular direction of rotation of drill bit 148 within one full rotation of the angular offset. Then, depending on direction of the detected geological drift or directional tendency, the angular rotation of drill bit 148 may be modified to allow an increased amount of drill bit 148 rotation to be spent in the direction opposite the direction of the determined geological drift or directional tendency trend and decreased amount of drill bit 148 rotation in the direction of the trend. The described control response adjustments result in decreasing the amount of wellbore creation in the direction of the trend and/or increasing the amount of wellbore creation in the direction opposite of the trend.

In some embodiments, the adjustment of rotation speed by BHA 149 can include cumulative functionality, such that when a first adjustment results in a first improvement of a drilling condition, a second adjustment that is larger in magnitude may be assumed to result in a second improvement that is also more beneficial with respect to the drilling condition. In various embodiments, BHA 149 (or surface steerable system 168) may consider a desired rotational speed of drill bit 148 as an unknown variable that is assumed to exist at a minima of one or more measured values (e.g., lateral vibration, stick-slip, etc.), such that a gradient descent algorithm can be used to calculate the desired rotational speed of drill bit 148.

Alterations in rotational speed of drill bit 148 may affect the interaction of cutting elements of drill bit 148 and a perimeter of borehole 106. For example, when the rotational speed of drill bit 148 is faster than the rotational speed of drill string 146 (such as with a CVT or a mud motor used with BHA 149), the cutting elements may bite more aggressively into the perimeter of borehole 106, which can enhance drilling efficiency, but may cause increased wear on drill bit 148. Furthermore, when the rotational speed of drill bit 148 is slower or in the opposite direction than the rotational speed of drill string 146, the cutting elements may bite less aggressively, which can reduce wear on the drill bit 148.

In addition to maximizing the operational lifetime of drill bit 148, such as by reducing unnecessary wear, adjusting the rotational speed of drill bit 148 can also affect the reactive forces applied to of drill bit 148 by borehole 106, which may contribute to certain drilling problems. For example, at certain rotational speeds of drill bit 148, the interaction of the cutting elements and the perimeter of borehole 106 may counteract other forces on BHA 149 that could otherwise contribute to drilling problems, which may be beneficial. However, at other rotational speeds of drill bit 148, the interaction can excite vibrations or forces that may cause drilling problems, which is not desirable. As explained above, BHA 149 (or surface steerable system 168) may be capable of processing measured values and determining rotational speeds of drill bit 148 to prevent the excitation of vibrations or forces that can cause a drilling problem or damage to certain drilling equipment.

In particular embodiments, BHA 149, the RSS tool, or surface steerable system 168 may further be equipped with processing capability for predicting an optimal rotational speed of drill bit 148 for a given drilling condition. A set point for the rotational speed of drill bit 148 can be selected by at least one of the following values:

-   -   an RPM of drill string 146;     -   an RPM of BHA 149;     -   a formation rock parameter; and     -   a reference value.         The formation rock parameter may be given by a category of a         known formation, by a well plan, or by data collected from         geological formation 102 being drilled through. The reference         value may be based on prior drilling experience, such as records         of previous wells drilled through similar formations or along         similar trajectories to borehole 106. For example, historical         data, simulations, calculations, or prior experience may be used         to determine that, for drill bit 148 and geological formation         102, a particular rotational speed is an optimal rotational         speed for drill bit 148, because the particular rotational speed         results in at least one of maximizing drilling efficiency,         minimizing tool wear, and minimizing vibration. Accordingly, in         some embodiments, BHA 149, the RSS, or surface steerable system         168 may detect a particular drilling condition, and select an         optimum rotational speed of drill bit 148, based on         calculations, simulations, data collected from prior wells, or         various combinations of sources. In particular, BHA 149, the         RSS, or surface steerable system 168 may detect the drilling         condition by monitoring vibrations and other variables to         determine the type of rock being drilled through, and based on a         current subterranean location of drill bit 148 relative to a         geological map or a well plan.

Referring now again to the drawings, FIGS. 11 and 12 depict various configurations of a rotary steerable BHA 149-1 and illustrate different methods of drill string and drill bit rotation. It is noted that the drawings in FIGS. 11 and 12 are schematic illustrations and may not be drawn to scale or perspective.

In FIGS. 11 and 12, drill string 146 is shown at a terminal portion relative to a surface direction 1106 and having a drill string axis 1108 in proximity to rotary steerable BHA 149-1. Drill string 146 accordingly is enabled to rotate about drill string axis 1108 under power from top drive 140 (not shown in FIG. 11I; see FIG. 1), as indicated by an angular velocity arrow 1110 representing an angular velocity α of drill string 146. Furthermore, rotary steerable BHA 149-1 is shown coupled to drill string 146 by means of a collar 1112, which may represent any type of generic threaded coupling.

In FIG. 11, an example of a drill string and drill bit rotation 1100 is shown with rotary steerable BHA 149-1 in a fixed angle configuration, similar to a bent sub. Accordingly, rotary steerable BHA 149-1 is shown including mechanism 1122 configured for bent sub functionality having a vertex 1124 along drill string axis 1108 and having an angle θ deflection about vertex 1124. As a result, drill bit 148 is coupled to mechanism 1122 along a drill bit axis 1128 that is deflected at angle θ from drill string axis 1108. In the fixed angle configuration of drill string and drill bit rotation 1100, drill string 148 does not rotate about drill bit axis 1128, but rather, angle θ rotates along with drill string 146 about drill string axis 1108, causing drill bit 148 to also rotate about drill string axis 1108, but in the fixed angle configuration with a fixed deflection of angle θ, resulting in a larger diameter of borehole 106.

In drill string and drill bit rotation 1100 of FIG. 11, the source of rotational power in drill string and drill bit rotation 1100 of FIG. 11 is top drive 140. Accordingly, in drill string and drill bit rotation 1100, rotary steerable BHA 149-1 may transmit control indications generated during drill string and drill bit rotation 1100 to steering control system 168, which may receive the control indication and may control top drive 140 and mud pump 152 (as included in a mud circulation system) to control the rotational speed of drill bit 148. In some embodiments, steering control system 168 may also communicate with rotary steerable BHA 149-1, such as to instruct rotary steerable BHA 149-1 to modify angle θ, as desired.

In FIG. 12, an example of a drill string and drill bit rotation 1200 is shown with rotary steerable BHA 149-1 in a rotary steerable configuration. Accordingly, rotary steerable BHA 149-1 is shown including mechanism 1130 configured for “universal joint” functionality about vertex 1124 along drill string axis 1108, and with CVT functionality to enable a transmission ratio between drill string rotation 1100 and a drill bit angle rotation 1114 that is independent of drill string rotation 1100, and having an angle θ deflection about vertex 1124. As a result, drill bit 148 is coupled to mechanism 1130 along drill bit axis 1128 that is deflected at angle θ from drill string axis 1108 at vertex 1124. In the rotary steerable angle configuration of drill string and drill bit rotation 1100, drill string 148 may rotate about drill bit axis 1128 at an angular velocity β that may be different from angular velocity α, as given by the transmission ratio. Furthermore, mechanism 1130 may be enabled to vary angle θ in order to drill curved trajectories of borehole 106.

In drill string and drill bit rotation 1200 of FIG. 12, drill string 146 may be rotated about drill string axis 1108 by top drive 140 at angular velocity α, while drill bit 148 is independently rotated about drill bit axis 1128 at angular velocity β. Accordingly, a net angular velocity of drill bit 148 with respect to geological formation 102 (not shown in FIG. 12; see FIG. 1) may be given by α+β. It is noted that angular velocity α and angular velocity β may have different magnitudes and different polarity (i.e., directions of rotation). Furthermore, the transmission ratio enabled by the CVT in mechanism 1130 may be set to unity in certain embodiments, such that α=β, while rotary steerable BHA 149-1 provides only universal-joint functionality by enabling the geostationary deflection of angle θ, which may be actively controlled by mechanism 1130. Further, it is noted that mechanism 1130 may be enabled to set angle θ to zero to enable drilling straight along drill string axis 1108 that is then aligned with drill bit axis 1128.

It is noted that in certain embodiments, in addition to or in replacement of the CVT functionality of mechanism 1130, a mud motor (not shown) may be used to drive rotation of drill bit 148 about drill bit axis 1128. In such a configuration (not shown), the mud motor is mounted between vertex 1124 and drill bit 148, and is subject to the deflection at angle θ. The use of the mud motor may provide various benefits or drilling scenarios, such as increased RPM, or the ability to perform slide drilling while drill string 1108 is rotated at a nominal angular velocity α for the purpose of relieving trapped torque in drill string 146 during the slide drilling, for example. Because the mud motor is controlled by the mud circulation system at surface 104 by steering control system 168, when a mud motor is used, rotary steerable BHA 149-1 may communicate with steering control system 168 to optimize drilling, as disclosed herein.

In drill string and drill bit rotation 1200 of FIG. 12, rotary steerable BHA 149-1 may be controlled from surface 104, such as by steering control system 168, which may be responsive to information that is encoded in the mud flow, irrespective of whether a mud motor is used for drilling. The mud flow may be controlled to set rotary steerable BHA 149-1, including mechanism 1130, to desired values for the angle θ and the transmission ratio of the CVT. Furthermore, an onboard controller (not shown) included with rotary steerable BHA 149-1 may send information back to surface 104 (e.g., to steering control system 168) that is indicative of a control indication for drilling control that the onboard controller has determined, based on measured values from sensors accessible to the onboard controller. The onboard controller of rotary steerable BHA 149-1 may also be independently capable of setting the angle θ and the transmission ratio of the CVT. Thus, in this manner, in drill string and drill bit rotation 1200, control of drilling parameters, such as rotational speed of drill bit 148 and a rotational direction of drill bit 148, may be controlled downhole by the onboard controller or may be controlled from surface 104 by steering control system 168 or may be controlled in a hybrid manner as desired.

Turning now to FIG. 13, an embodiment of method 1300 for RSS drilling is illustrated in flow chart form. Method 1300 may represent an algorithm used in the context of drill string and drill bit rotation 1100 and 1200 (see FIGS. 11 and 12). It is noted that certain operations described in method 1300 may be optional or may be rearranged in different embodiments. Method 1300 may be implemented by a computer system executing one or more computer software programs. Such a computer system may comprise a part of the surface control system 168 or may be a separate computer system. Such a computer system may be implemented entirely at a surface location, entirely downhole, or with a combination of elements both at a surface location and downhole.

Method 1300 may begin at step 1302 by monitoring vibration of a drill string including a rotary steerable BHA. At step 1304 a decision is made whether the vibration is within an acceptable threshold. When the result of step 1304 is YES, and the vibration is within an acceptable threshold, method 1300 may loop back to step 1302. When the result of step 1304 is NO, and the vibration is not within an acceptable threshold, at step 1306 the rotation speed of the drill bit is adjusted. At step 1308, the vibration of the drill string is again monitored. At step 1310, a decision is made about how the vibration is after the adjustment in step 1306, based on the monitoring in step 1308. When the result of step 1310 is that the vibration is within the acceptable threshold (which may be the same threshold as applied in step 1304), method 1300 may end at step 1312. When the result of step 1310 is that the vibration is improved but is not within the acceptable threshold, method 1300 may loop back to step 1306. When the result of step 1310 is that the vibration is worsened (e.g., further from the threshold than before) and not within the acceptable threshold, at step 1314, the rotation direction of the drill bit may be reversed. After step 1314, method 1300 may loop back to step 1306. In the method 1300, the vibration of the drill string may involve the amplitude of a vibration, the frequency of the vibration, or a combination thereof.

It is to be understood that the systems and methods of the present disclosure may involve computer programming that determines whether a value exceeds a threshold value, falls below a threshold value, or falls outside of a target range. In addition, the threshold values and the target range may be determined by the computer system, such as based on information provided to the system by an operator or based on information received while drilling. The threshold values and target ranges may change during drilling of a well, such as based on the section of the well being drilled, the geological formation(s) being drilled, the equipment used for drilling, and/or the drilling parameters of the drilling (e.g., WOB, ROP, DP, mud flow rate, torque, etc.) In addition, it is to be understood that multiple threshold values or target ranges may apply, and that different remedial or corrective actions may be taken depending on the threshold ranges involved. For example, the system may be programmed so that drilling is adjusted by a particular amount of angular velocity if a first threshold value is exceeded, but if a second threshold value is also exceeded, the drilling may be adjusted by a second particular amount of angular velocity (e.g., a greater amount than the first amount).

Turning now to FIG. 14, an embodiment of method 1400 for RSS drilling is illustrated in flow chart form. Method 1400 may represent an algorithm used in the context of drill string and drill bit rotation 1100 and 1200 (see FIGS. 11 and 12). It is noted that certain operations described in method 1400 may be optional or may be rearranged in different embodiments.

Method 1400 may begin at step 1402 by drilling a borehole using a rotary steerable BHA coupled to a drill string, where the drill string is enabled for rotation by a top drive in a drilling rig, and a drill bit is coupled to the rotary steerable BHA. At step 1404, using a sensor included with the rotary steerable BHA, a drilling condition indicative of a vibrational load on the drill string is detected, where the vibrational load exceeds a threshold. At step 1406, based on the drilling condition, a control indication that drilling parameters associated with the drilling by the drill string should be modified to reduce the vibrational load is generated by the rotary steerable BHA. In the method 1400, the vibration of the drill string may involve the amplitude of a vibration, the frequency of the vibration, or a combination thereof.

After step 1406, two variants are depicted in method 1400 that describe surface control and downhole control, respectively, of a response to the control indication generated at step 1406. In a first variant of method 1400, in which surface control is performed by surface control system 168, after step 1406 at step 1408, the control indication is transmitted to the surface to a steering control system enabled to control the drilling parameters for the drill string, where the steering control system 168 is enabled to control the top drive and a mud circulation system. After step 1408, at step 1410, updated drilling parameters are received from the steering control system to reduce the vibrational load. In a second variant of method 1400, in which downhole control is performed by rotary steerable BHA 149-1, after step 1406 at step 1412, based on the control indication, by the rotary steerable BHA causes rotation of the drill bit to be modified to reduce the vibrational load.

As disclosed herein, a system and method for optimizing drilling with a rotary steerable system may monitor downhole signals associated with vibrational loads along a drill string during drilling. A downhole controller at a rotary steerable bottom-hole adapter may generate a control indication for modifying drilling parameters of a drill bit in response to detecting harmful vibrational loads for the drill string. A modification of the drilling speed and direction of the drill bit used for drilling may be performed based on the control indication. It is believed that providing the RSS tool with the computer system and programming to detect vibrational loads and directional trends, and then automatically correct for them when appropriate, allows a much faster response to excessive vibrational loads than detecting and addressing them with traditional downhole sensors, surface sensors and surface control systems. Nonetheless, it is possible to implement the systems and methods of the present disclosure with surface systems in addition to or in lieu of computer control systems in the RSS tool.

In another embodiment, the RSS tool may have one or more processors, memory with instructions stored therein, with the instructions executable by the one or more processors and with the processors configured to receive information from the one or more sensors described above. The RSS tool can also be configured to send information to the MWD system in the BHA and thus send information to the surface, such as by mud telemetry, where the surface control system 168 or another control system may receive and analyze the information from the RSS tool and take appropriate remedial action. For example, with such a configuration, the RSS tool can receive information from the downhole sensors regarding the vibration of the drill string, determine whether the amplitude, frequency, or both of such vibration is within a threshold therefor, and then send the result of the determination to the surface, where the result information is received by a surface control system. The surface control system in this example can be configured to send one or more control signals to adjust one or more of weight on bit (WOB), differential pressure (DP), mud flow rate, and/or other drilling parameters. In one example, the surface control system may be configured to increase WOB, the RSS tool can then receive updated information regarding the vibration of the drill string in response to the increased WOB, determine whether the vibration has improved or worsened (e.g., moved closer to or within the threshold therefor) responsive to the increased WOB, then send this determination information to the surface. The control system can receive this updated information from downhole provided by the RSS tool and, if the determination information is that the vibration has improved, may then further increase the WOB. If no improvement is detected, or no improvement of a certain amount is detected, then no further increase in WOB need be made by the surface control system. If, however, WOB is increased, and a determination is made that the vibration has worsened (e.g., increased in amplitude or frequency), then the surface control system may send one or more control signals to decrease WOB. If decreasing WOB is then determined to reduce the vibration by the RSS tool, then the surface control system in response to such a determination may further decrease WOB. The increases or decreases of drilling parameters such as WOB, DP, torque, mud flow rate, and the like may be made in predetermined increments, or may be made in amounts responsive to the amplitude and/or frequency of the vibrations. It should be understood that one or more of such drilling parameters may be adjusted in addition to adjustment of angular rotation velocity and/or angular position of the drill bit.

The above disclosed subject matter is to be considered illustrative, and not restrictive, and the appended claims are intended to cover all such modifications, enhancements, and other embodiments which fall within the true spirit and scope of the present disclosure. Thus, to the maximum extent allowed by law, the scope of the present disclosure is to be determined by the broadest permissible interpretation of the following claims and their equivalents, and shall not be restricted or limited by the foregoing detailed description. 

What is claimed is:
 1. A system for improved drilling, the system comprising: a processor; a memory coupled to the processor, wherein the processor contains instructions executable by the processor for: receiving information from a sensor in a bottom hole assembly (BHA) coupled to a drill string, wherein the BHA is coupled to a drill bit drilling a borehole; detecting, responsive to the information from the sensor, a drilling condition indicative of a vibrational load; determining whether the vibrational load falls outside a target range therefor, and if the vibrational load falls outside the target range therefor, then generating, by the rotary steerable BHA, a control indication that a drilling parameter associated with the drilling of the borehole should be modified.
 2. The system of claim 1 wherein the vibrational load is at least one of an axial vibrational load, a radial vibrational load, and a torsional vibrational load.
 3. The system of claim 2, wherein the instructions further comprise instructions for transmitting the control indication to a control system at a surface location, wherein the control system is enabled to control the drilling parameter.
 4. The system of claim 3, wherein the instructions further comprise instructions for, responsive to transmitting the control indication, receiving updated information from the sensor, determining therefrom an updated vibrational load, determining whether the updated vibrational load is closer to the threshold than the vibrational load and, if the updated vibrational load is closer to the threshold than the vibrational load, generating a second control indication to further adjust the drilling parameter.
 5. The system of claim 1, wherein the drill bit is enabled to rotate by the BHA independently of the rotation of the drill string by the drill rig, and wherein the instruction further comprise instructions for, based on the control indication, causing, by the rotary steerable BHA, angular velocity or angular position of the drill bit to be modified to thereby reduce the vibrational load.
 6. The system of claim 5, wherein the causing, by the rotary steerable BHA, the rotation of the drill bit to be modified further comprises instructions for adjusting a continuously variable transmission (CVT) in the rotary steerable BHA, the CVT being coupled to the drill bit and driving the rotation of the drill bit.
 7. The system of claim 5, wherein the causing, by the rotary steerable BHA, rotation of the drill bit to be modified further comprises instructions for causing a mud motor coupled to the drill bit and driving the rotation of the drill bit to be adjusted.
 8. The method of claim 5, wherein the causing, by the rotary steerable BHA, the rotation of the drill bit to be modified further comprises at least one of: instructions for adjusting a rotational speed of the drill bit; and instructions for reversing a rotational direction of the drill bit.
 9. The system of claim 1, further comprising instructions for modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit with respect to a rotational axis of the drill string that is rotating in proximity to the rotary steerable BHA.
 10. The system of claim 9, wherein the instructions for modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit further comprise instructions for setting the angle to a fixed value with respect to the drill string, wherein the angle rotates with the drill string.
 11. The system of claim 9, wherein the instructions for modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit further comprise instructions for continuously setting the angle to maintain the drill bit in a geostationary location when the drill string rotates and the drill bit rotates.
 12. The system of claim 1, wherein the drilling condition comprises at least one of a stick-slip condition and a lateral vibration.
 13. The system of claim 1, wherein the sensor comprises at least one of: a microelectronics system (MEMS) gyroscope; a MEMS accelerometer, and a magnetometer.
 14. A method for improved drilling, the method comprising: drilling a borehole using a bottom hole assembly (BHA) coupled to a drill string, wherein the drill string is enabled for rotation by a drilling rig, and wherein a drill bit is coupled to the BHA; detecting, using a sensor included with the BHA, a drilling condition indicative of a vibrational load on the drill string, wherein the vibrational load exceeds a threshold for the drill string; and based on the drilling condition, generating, by the BHA, a control indication that a drilling parameter associated with the drilling by the drill string should be modified to reduce the vibrational load.
 15. The method of claim 14, further comprising: transmitting the control indication to the surface to a steering control system enabled to control the drilling parameters for the drill string, wherein the steering control system is enabled to control the top drive and a mud circulation system.
 16. The method of claim 15, further comprising: responsive to transmitting the control indication, receiving updated drilling parameters from the steering control system to reduce the vibrational load.
 17. The method of claim 14, wherein the drill bit angular rotation is enabled to rotate by the rotary steerable BHA independently of the rotation of the drill string by the top drive, and further comprising: based on the control indication, causing, by the rotary steerable BHA, rotation of the drill bit to be modified to reduce the vibrational load.
 18. The method of claim 17, wherein the causing, by the rotary steerable BHA, the angular rotation of the drill bit to be modified further comprises: adjusting a continuously variable transmission (CVT) included in the rotary steerable BHA, the CVT being coupled to the drill bit and driving the angular rotation of the drill bit.
 19. The method of claim 17, wherein the causing, by the rotary steerable BHA, angular rotation of the drill bit to be modified further comprises: causing a mud motor coupled to the drill bit and driving the rotation of the drill bit to be adjusted.
 20. The method of claim 17, wherein the causing, by the rotary steerable BHA, the angular rotation of the drill bit to be modified further comprises at least one of: adjusting an angular rotational speed of the drill bit; and reversing an angular rotational direction of the drill bit.
 21. The method of claim 14, further comprising: modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit with respect to a rotational axis of the drill string that is rotating in proximity to the rotary steerable BHA.
 22. The method of claim 21, wherein the modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit further comprises: setting the angle to a fixed value with respect to the drill string, wherein the angle rotates with the drill string.
 23. The method of claim 21, wherein the modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit further comprises: continuously setting the angle to maintain the drill bit in a geostationary location when the drill string rotates and the drill bit rotates.
 24. The method of claim 14, wherein the drilling condition comprises at least one of: a stick-slip condition; and a lateral vibration.
 25. The method of claim 14, wherein the sensor comprises at least one of a microelectronics system (MEMS) gyroscope; a MEMS accelerometer; and a magnetometer.
 26. A method for improved drilling, the method comprising: drilling a borehole using a rotary steerable bottom hole assembly (BHA) coupled to a drill string, wherein the drill string is enabled for rotation by a drilling rig and wherein a drill bit is coupled to the BHA, wherein the angular position and angular velocity of the drill bit may be controlled independently of the rotation of the drill string by the rig; detecting, using a sensor included in the BHA or a sensor located at the surface, a drilling condition; determining whether a correction of the drilling condition is indicated, due to the drilling condition being less than a minimum threshold therefor, exceeding a maximum threshold therefor, or falling outside a target range therefor; and responsive to a determination that a correction of the drilling condition is indicated, generating, by the BHA, a control indication that the angular position, the angular velocity, or both, of the drill bit should be modified.
 27. The method of claim 26 further comprising modifying the angular position, the angular velocity, or both, of the drill bit responsive to the control indication.
 28. The method of claim 26, further comprising: transmitting the control indication to a steering control system enabled to control the drilling parameters for the drill string, wherein the steering control system is located at the surface and is enabled to control the top drive and a mud circulation system.
 29. The method of claim 28, further comprising: responsive to transmitting the control indication, receiving updated drilling parameters from the steering control system to reduce the vibrational load.
 30. The method of claim 26, wherein the drill bit is enabled to rotate by the rotary steerable BHA independently of the rotation of the drill string by the top drive, and further comprising: based on the control indication, causing, by the rotary steerable BHA, angular rotation of the drill bit to be modified by adjusting a continuously variable transmission (CVT) included in the rotary steerable BHA, the CVT being coupled to the drill bit and driving the rotation of the drill bit.
 31. The method of claim 30, wherein the causing, by the rotary steerable BHA, angular rotation of the drill bit to be modified further comprises: causing a mud motor coupled to the drill bit and driving the angular rotation of the drill bit to be adjusted.
 32. The method of claim 30, wherein the causing, by the rotary steerable BHA, the angular rotation of the drill bit to be modified further comprises at least one of: adjusting an angular rotational speed of the drill bit; and reversing a rotational direction of the drill bit.
 33. The method of claim 26, further comprising: modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit with respect to a rotational axis of the drill string that is rotating in proximity to the rotary steerable BHA.
 34. The method of claim 33, wherein the modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit further comprises: setting the angle to a fixed value with respect to the drill string, wherein the angle rotates with the drill string.
 35. The method of claim 33, wherein the modifying, by the rotary steerable BHA, an angle of a drilling axis of the drill bit further comprises: continuously setting the angle to maintain the drill bit in a geostationary location when the drill string rotates and the drill bit rotates.
 36. The method of claim 26, wherein the drilling condition comprises at least one of: a stick-slip condition; and a lateral vibration.
 37. The method of claim 26, wherein the sensor comprises at least one of: a microelectronics system (MEMS) gyroscope; a MEMS accelerometer, and a magnetometer. 